Supercritical carbon dioxide for fracking and hydrocarbon recovery

ABSTRACT

A method of producing a hydrocarbon from a hydrocarbon deposit in a fracked well using CO 2  in supercritical form as a fracking fluid. The fracking fluid does not include any water or particulates introduced from a source external to the well. In some instances, CO 2  can be sequestered. In some cases, the hydrocarbon deposit is green shale or young shale.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of co-pending international application PCT/US 18/32715, filed May 15, 2018 designating the United States, and claims the benefit and priority thereof, which PCT application in turn claimed priority to and the benefit of then co-pending U.S. provisional patent application Ser. No. 62/506,600, filed May 15, 2017, each of which applications is incorporated herein by reference in its entirety.

FIELD OF THE INVENTION

The invention relates to manipulation of hydrocarbons in general and particularly to a system and method that employs carbon dioxide as a working fluid.

BACKGROUND OF THE INVENTION

The current fracking process is applied in a slightly different manner by oil and gas field service providers as each provider has custom built equipment and variations of chemical blends as determined by both the geo-mechanical nature of the well and the development history within the company. The conventional sequence of operation is first drilling to reach a zone believed to contain gas or oil, fracking the zone, and producing the gas or oil. As the production of gas or oil decays over time, the well may require additional fracking periods to allow the rate of production to be improved.

The actual fracking commences after the vertical, bend, and horizontal parts of the well have been drilled and the appropriate well casing placed (the vertical portion encased as drilling is halted just below the water table to ensure that no transference of material from the well will enter the water table either during drilling or production). At this point the well is a hole in the ground with cement barriers between the pipe, the shale formations, and the water table.

The fracking process requires high pressure, which uses a lot of horsepower to drive the fluid down more than a mile into the well. There is also required science to calculate the mixtures of the fracking fluid chemicals, water, and sand required to fracture the shale within the pay zone. As one equipment provider has stated, “the more horsepower I can deliver to the well, the happier the well stimulation operator will be.” To accomplish this goal, a missile (a manifold containing a low pressure loading side and a high pressure delivery side, around which the operation centers) is placed over the well. On one side are attached 5 to 6 semi-trailer trucks containing pressure pumps to deliver the maximum available pumping horsepower. On the other side are positioned sand, water, and chemical trucks to deliver these materials. There is also a hydration truck which is used to blend the chemicals with the water to form a gel which is then mixed with the sand. The gelling process allows for a much higher quantity of sand to be fed downhole. The sand/gel blender delivers the mixture of sand, water, and chemicals to the low pressure side of the missile. The missile is then pressurized and released downhole where it can crack the rock open leaving the sand behind to prop the fissure open allowing for the gas or oil production once the fracking process is completed.

To enhance the effectiveness of fracking, the liquid pumped into the rock is mixed with chemicals and one or more forms of “proppant,” commonly sand. Proppant particles are trapped in cracks generated by fracking and help “prop” them open, facilitating the continued flow of gas through the fractures. For decades, operators have experimented with various combinations and concentrations of gels, proppants, and water (and sometimes foam), often varying the technique for different formations. The nature of the fracking fluid and proppant is generally tailored to the particular geological formation being fracked. For the types of shale gas formations of concern here, the fracking mixture tends to be at least about 98% to 99% water and sand, with the remainder comprising any of a number of substances. These substances can include “friction reducing” agents such as polyacrylamides, biocides such as methanol to kill bacteria, “scale inhibitors” such as hydrochloric acid, and various other materials such as guar gum, borate salts, and isopropanol that can help optimize any of a variety of fracking fluid properties such as viscosity and the ability to carry and release proppant. Proppants can also be varied in terms of grain size, shape, coating, or source. Some form of sand remains the dominant choice, but at one time or another fracturing service companies have tried a host of alternatives, including plastic pellets, steel shot, Indian glass beads, aluminum pellets, high-strength glass beads, rounded nut shells, resin coated sands, sintered bauxite, and fused zirconium. Industry players have apparently been willing to look far and wide for materials that could help improve fracturing solutions or proppants: in the 1970s, energy companies borrowed chemical agents from the plastic explosives industry.”

The traditional method of fracking is dependent on horsepower and not chemistry. In fact, many service providers are quick to point out that the chemicals added to the frack fluid are not to interact with the shale and no chemistry is completed underground. The goal of the chemicals is to help hold the sand in the place and to assist in adding “punch” to the fluid as it hits the shale. In short, this process is one of brute force against the shale which is repeated over and over until the fracking step is completed.

A typical well can have 20 to 25 stages along the horizontal which need to be fracked. This means the process of blending, pressurizing, and cracking can last 20 to 25 hours, approximately one hour per stage needed to be fracked. During the course of this operation, hundreds of operational parameters are measured and adjusted to optimize the operation. For each stage the process and mixtures of chemicals, water, and sand are optimized. Once the process is completed, the flow is reversed and the downward pressure removed from the well. The fracking equipment is removed from the site and the well is set up for production. Within a couple of days, the release of all the pressure pushed down well will be fully reversed and gas production will begin and continue for some time.

A typical well can consume 2 to 10 million gallons of water (approximately 1,400 truck loads), more than 4 million pounds of proppant, and 80 to 330 tons of chemicals. Estimates of the amount of fluid that remains underground range from less than 5% to more than 90%, so a “typical” calculation of waste material for disposal is difficult. However, the State of Pennsylvania, where much of the Marcellus Shale fracking is occurring, has recorded an amount in excess of 610 million gallons of waste fluids from fracking was collected during 2015 (from approximately 35,000 wells). The US Geological Survey found that flowback, which comprises much of this waste, contains a variety of materials such as radionuclides, heavy metals, brines, and hazardous organics which make the treatment of this waste stream difficult and expensive.

In the conventional process, large numbers of water trucks, a large number of trucks full of sand, and trucks containing hazardous chemicals must be brought to the well head.

The use of CO₂ as an injection material for the fracturing of shales under high pressure conditions is not novel.

Known in the prior art is Bullen et al., U.S. Pat. No. 4,374,545, issued Feb. 22, 1983, which is said to disclose a new and improved method of fracturing an underground stratigraphic formation penetrated by a well bore including the steps of pumping a stream of liquified gas into the formation to cause the fracturing thereof and then introducing proppants directly into the stream of liquified gas for injection of the proppants into the fractures. Prior to introducing the proppants into the liquid gas stream, they are cooled and pressurized to the storage temperature and pressure of the liquified gas.

Also known in the prior art is Bullen et al., U.S. Pat. No. 4,701,270 issued Oct. 20, 1987, which is said to disclose a viscosity-increased liquid carbon dioxide fracturing fluid is provided for the treatment of subterranean gas-bearing formations. The composition comprises liquid carbon dioxide which has been thickened by the addition of a small amount of a copolymer which is the reaction product of liquid carbon dioxide and an alkene oxide, preferably propylene oxide. The use of the copolymer thickener provides a CO₂ fracturing fluid which may be pumped at a high rate, will not readily boil or foam, will carry a propping agent and will completely degrade within the formation.

Also known in the prior art is Luk et al., U.S. Pat. No. 5,515,920, issued May 14, 1996, which is said to disclose a method of fracturing an underground formation penetrated by a well bore comprising the steps of forming a first pressurized stream of liquified gas, introducing proppants into the first stream for transport of the proppants in the first stream, pressurizing and cooling the proppants to substantially the storage pressure and temperature of the liquified gas prior to introducing the proppants into the first stream, forming a second pressurized stream of fracturing fluid, introducing proppants into the second stream for transport therein, and admixing the first and second streams to form an emulsion for injection into the formation at a rate and pressure to cause the fracturing thereof.

Also known in the prior art is Amin et al., U.S. Pat. No. 6,184,184, issued Feb. 6, 2001, which is said to disclose an encapsulated breaker for a fracturing fluid for use in fracturing subterranean formations comprising: a hydrocarbon base; neutralized alkyl phosphate esters completed with metallic cations, to form a gel, in said hydrocarbon base.

Also known in the prior art is Gupta, U.S. Pat. No. 6,509,300, issued Jan. 21, 2003, which is said to disclose a fracturing fluid is disclosed consisting of an emulsion having a continuous phase of a liquified gas, a discontinuous phase of a hydrocarbon, and a surfactant soluble in the two phases. The surfactant is preferably a hydrofluoroether.

Also known in the prior art is Peterson, Canadian Pat. No. 687,938, issued Jun. 2, 1964, which is said to disclose the treatment of wells for fracturing surrounding earth formations to increase productivity by increasing lateral drainage channels within a given reservoir.

Also known in the prior art is Hussin, Canadian Pat. No. 1,047,393, issued Jan. 30, 1979, which is said to disclose a method of forming fractures and placing proppants therein, which comprises creating a foam having a down-well Mitchell quality of from about 0.53 to 0.99 and passing that foam down the well in admixture with a particulate proppant in an amount of up to three pounds of proppant per gallon of foam, then decreasing the gas volume in said foam, whereby the proppant carrying medium being passed down the well changes from a foam to a liquid. The proppant concentration is decreased as-the change occurs from foam to liquid so that the proppant material will not deposit out prematurely in the well. Once liquid flow has been established, the proppant to fluid ratio is gradually increased and the fracture of the formation is continued with liquid and proppant. The liquid is capable of carrying an amount of proppant greater than that which could be carried by the foam, namely from four to ten pounds per U. S. gallon.

Also known in the prior art is Hussin, Canadian Pat. No. 1,122,896, issued May 4, 1982, which is a reissue of Canadian Pat. No. 1,047,393. It is said to disclose a method of forming fractures and placing proppants therein, which comprises creating a foam having a down-well Mitchell quality of from about 0.53 to 0.99 and passing that foam down the well in admixture with a particulate proppant in a. concentration of up to three pounds of proppant per gallon of foam, then decreasing the gas ratio in said foam, whereby the proppant carrying medium being passed down the well changes from a foam to a liquid. The proppant concentration in the fluid is decreased as the change occurs from foam to liquid. so that the proppant material will not deposit out prematurely. Once liquid flow has been established, the proppant to fluid ratio is gradually increased and the fracture of the formation is continued with liquid and proppant. The liquid is capable of carrying a concentration of proppant greater than that which could be carried by the foam.

Also known in the prior art is Bullen et al., Canadian Pat. No. 1,134,258, issued Oct. 26, 1982, which is said to disclose a new and improved method of fracturing an underground stratigraphic formation penetrated by a well bore including the steps of pumping a stream of liquified gas into the formation to cause the fracturing thereof and then introducing proppants directly into the stream of liquified gas for injection of the proppants into the fractures. Prior to introducing the proppants into the liquid gas stream, they are cooled and pressurized to the storage temperature and pressure of the liquified gas.

See also for example the following patent literature:

An overview of hydraulic fracturing and other formation stimulation technologies for shale gas production. See also European Commission, JRC Technical Reports, Luca Gandossi, 2013; An overview of hydraulic fracturing and other formation stimulation technologies for shale gas production, A Kibble, T Cabianca, Z Daraktchieva, T Gooding, J Smithard, G Kowalczyk, N P McColl, M Singh, S Vardoulakis and R Kamanyire, PHE-CRCE-002, 2015; and Decline Curve Analysis of Shale Oil Production, The Case of Eagle Ford, Linnea Lund, 2014 Master's Thesis, Uppsala University; October 2014).

The use of CO₂ as a green solvent is not novel. In fact, the science of “green chemistry” is focused on the replacement of harsher and less environmentally friendly solvents by CO₂. A wide range of successes have been published and a large number of patents exist. In situ upgrading of oil coming from the ground has also been studied extensively.

In the application of CO₂ for the fracturing of gas and oil shales and uplifting of the natural gas or oil released, CO₂ has been treated as a direct replacement for other media, primarily water. This can be supported by the 2016 comments of General Electric “CO₂ for fracturing is more than a decade away as novel proppants need to be discovered such that the proppant can be readily carried in the CO₂ which has a much lower inherent density than the water it replaces.” This focus on supporting proppants and substitution for water can be found in patents as well.

In literature studies (see EU report), CO₂ is listed as a replacement of water for high pressure hydraulic fracturing of the shales.

Some literature searches show that carbon dioxide may be capable of decaying the kerogen within the shale enabling this proposed process to work. Reports from the 1980s and more recently between 2009 and 2016 (see: Numerical study of a stress dependent triple porosity model for shale gas reservoirs accommodating gas diffusion in kerogen, Journal of Natural Gas Science and Engineering, Guijie Sang, Derek Elsworth, Xiexing Miao, Xianbiao Mao, Jiehao Wang; The influence of CO₂ mitigation incentives on profitability of eucalyptus production on clay settling area in Florida, Matthew Langholtza, Douglas R. Carter, Donald L. Rockwood, Janaki R. R. Alavalapatic, Science Direct, 2009) show that the cracking of Kerogen can be completed under low pressure exposure to CO₂. A 1986 study shows these effects on shales that are not traditionally considered oil or gas bearing due to the young age of the shales. The ability to release gas and oil from younger, shallower shales can open up new sites and larger quantities of natural resources for extraction. A process which can focus on these young shales may be unique only in the application to shale which was not thought to be accessible.

There is a need for improved systems and methods for fracking and production of oil and gas.

SUMMARY OF THE INVENTION

We have developed a low pressure, water-, hazardous chemical-, and proppant-free process for the extraction of natural gas and oil from shale. The process uses an environmentally friendly supercritical fluid for the extraction process significantly reducing the environmental impact while delivering cost savings in treatment of the water prior to hydraulic fracturing processes as well as the need for the remediation of water post hydraulic fracturing. Our process does not use water or particulates, such as sand, that are provided from a source external to the well. Water that is incidentally or naturally present in the well, and particulates that may be present or that are generated inside the well, may be employed. The process uses the supercritical fluid as a solvent to break down the shale and release the gas and oil trapped in the shale and between shale layers. The shale that is not broken down with the supercritical fluid becomes a powder which acts as a proppant within the opening fissures in the shale and helps in the release of gas and oil trapped within the shale. In other words, the proppant that is generated in situ by the extraction of gas and oil from a shale, including a green shale, or young shale, is then employed as a proppant. No proppant is provided as particulates introduced from an external source into the well.

According to one aspect, the invention features a method of producing a hydrocarbon from a hydrocarbon-bearing deposit, comprising the steps of: drilling a well into the hydrocarbon-bearing deposit; fracking the hydrocarbon-bearing deposit using CO₂ in the form of supercritical CO₂ as the fracking fluid, the fracking fluid lacking any water or particulates added from a source external to the well; and producing a hydrocarbon product from the well, the hydrocarbon product having a form selected from the group consisting of liquid form and gaseous form.

In one embodiment, the method further comprises the step of sequestering at least some of the CO₂ in the well.

In another embodiment, the method further comprises the step of sequestering at least some of the CO₂ in a different well.

In yet another embodiment, the hydrocarbon-bearing deposit is green shale.

In a further embodiment, the hydrocarbon-bearing deposit is young shale.

In still another embodiment, the fracking fluid is introduced using low pressure.

The foregoing and other objects, aspects, features, and advantages of the invention will become more apparent from the following description and from the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The objects and features of the invention can be better understood with reference to the drawings described below, and the claims. The drawings are not necessarily to scale, emphasis instead generally being placed upon illustrating the principles of the invention. In the drawings, like numerals are used to indicate like parts throughout the various views.

FIG. 1 through FIG. 6 appear as FIG. 1 through FIG. 6, respectively, in U.S. Pat. No. 5,515,920.

FIG. 1 (Prior Art) is a block diagram of the hydraulic fracturing system combining proppants with liquid CO₂.

FIG. 2 (Prior Art) is a pressure-temperature plot for CO₂ in the region of interest with respect to the method of well fracturing illustrated in FIG.

FIG. 3 (Prior Art) is a sectional view taken along the longitudinal axis of the proppant tank illustrated schematically in FIG. 1.

FIG. 4 (Prior Art) is a partially sectional view of the proppant tank of FIG. 3.

FIG. 5 (Prior Art) is a more detailed view of the tank of FIGS. 3 and 4.

FIG. 5a (Prior Art) is a cross-sectional view of the tank illustrated in FIG. 5 at the section identified by arrows A, in which tank 20 may be fitted with baffle plates 21 to direct the proppants toward a helically wound auger 26 passing along the bottom of tank 20 in a direction towards conduit 5 via an auger tube 9.

FIG. 5b (Prior Art) is a cross-sectional view of the tank illustrated in FIG. 5 at the section identified by arrows B.

FIG. 6 (Prior Art) is a block diagram of a hydraulic fracturing system.

FIG. 7 (Prior Art) is a schematic illustration of a well fracturing system employing the fracturing fluid of the invention, which Figure appears in U.S. Pat. No. 4,701,270.

DETAILED DESCRIPTION

We have developed a process of utilizing CO₂ for the extraction of hydrocarbons from shales by injection of the CO₂ into the ground while in a supercritical state. The CO₂ acts as a chemical solvent and breaks the shale releasing the gas and/or oil. In the process of acting as a solvent, some portion of the CO₂ will bond with the shale and be left in the ground. Optimizing this process in such as manner as to leave a large quantity of CO₂ in the ground as a sequestration of the gas would be environmentally advantageous.

Kerogen is a mixture of organic chemical compounds that make up a portion of the organic matter in sedimentary rocks. It is insoluble in normal organic solvents because of the high molecular weight (upwards of 1,000 daltons or 1000 Da; 1 Da=1 atomic mass unit) of its component compounds. The soluble portion is known as bitumen. When heated to the right temperatures in the Earth's crust, (oil window c. 50-150° C., gas window c. 150-200° C., both depending on how quickly the source rock is heated) some types of kerogen release crude oil or natural gas, collectively known as hydrocarbons (fossil fuels). When such kerogens are present in high concentration in rocks such as shale, they form possible source rocks. Shales rich in kerogens that have not been heated to a warmer temperature to release their hydrocarbons may form oil shale deposits.

The method of the invention acts chemically on the shale and breaks down the kerogen. This releases bound hydrocarbons and fractures the shale allowing the release of trapped gas and oil. The method can act in the same manner on less mature shales, easier to access shales, shales which currently are not gas or oil bearing with traditional methods, and currently inaccessible shales without the use of hazardous chemical additives. The net result is a low cost, widely adaptable method of gas extraction and recovery which has a lower impact on the environment.

The method is expected to exploit the properties of supercritical carbon dioxide (scCO₂) as a working fluid, including very low surface tension; tunable density; and total miscibility with CH₄, to penetrate tight gas-bearing shales and entrain/remove the trapped CH₄. The CO₂/CH₄ mixture thus produced is expected be separated and the CO₂ recycled for further extraction. No proppant is expected be used as the reaction between the scCO₂ and the shale would result in fracturing of the shale into a powder, which itself is expected to assist in propping the fracture open and near the source reaction (injection point) so as to transform the entire region into a powder through which the gases could pass. A well which uses this process is expected not to experience a significant change in well pressure during or after the stimulation event. This significantly reduces the potential for a seismic event associated with the use of the process. In addition, without a drop in production over time, the well would be expected to have a longer useful lifespan and result in significantly higher yields.

This method, which utilizes supercritical carbon dioxide as a chemical solvent for cracking the shale and extraction of the natural gas is a water-free gas recovery process. It changes the tight structure of the shale into a fine powder, which results in facile release of the natural gas from the shale. This conversion of shale to powder has been observed in laboratory experiments. Hence, it allows for the user to tap into less mature and currently inaccessible shales without the use of water or chemical additives, while utilizing typical wellhead development methods and typical methods for hydraulic fluid fracturing techniques. The net result is expected to be a low cost, widely adaptable method of gas extraction and recovery which significantly reduces the impact on the environment. This method is expected to provide solutions to the recovery of natural gas from some of the more inaccessible or more naturally fractured gas fields.

The process presented here is a simple and efficient procedure for recovery of natural gas from shales: 1. without the use of water; 2. without the use of chemicals that can be harmful to the ground water; and 3. using a method that will remove the threat of seismic effects of the natural gas recovery caused by traditional and widely used methods. As such, three of the largest obstacles of environmental concern are addressed by this process. It will not use water or cause contamination of groundwater, it will not cause seismic activity, sinkholes, or earthquakes, and it doesn't utilize hazardous chemicals.

In one embodiment, the working fluid is carbon dioxide (CO₂) is a supercritical state (supercritical CO₂ or scCO). The scCO may have chemicals admixed therein, which chemicals, such as a hydrocarbon (for example methane, CH₄) are dissolved in the scCO. Admixed chemicals that can in different embodiments can include non-polar chemicals such as CH₄, polar chemicals such as methanol, or ethanol, and/or organic chemicals (e.g., methane, methanol). However, it is to be understood that the scCO is the solvent, and is present in appreciable excess as compared to any admixed chemical. Water is not used as an admixed chemical. However, it is possible that groundwater (e.g., water present in the location that the well is drilled or within the fracked region of interest) may become added to the working fluid without changing the feature of the invention that no water is deliberately added to the fluid at a location external to the well.

In some embodiments, the scCO amounts to at least 70% of the working fluid. In other embodiments, the scCO amounts to at least 75% of the working fluid. In other embodiments, the scCO amounts to at least 80% of the working fluid. In other embodiments, the scCO amounts to at least 85% of the working fluid. In other embodiments, the scCO amounts to at least 90% of the working fluid. In other embodiments, the scCO amounts to at least 95% of the working fluid. In other embodiments, the scCO amounts to at least 96% of the working fluid. In other embodiments, the scCO amounts to at least 97% of the working fluid. In other embodiments, the scCO amounts to at least 98% of the working fluid. In other embodiments, the scCO amounts to at least 99% of the working fluid.

It is believed that the method can operate at lower pressures than are required for conventional fracking methods.

The method is expected to provide the ability to sequester CO₂ as well.

In the application of the CO₂ enhanced gas and oil recovery method that is described herein, there is an opportunity to sequester some portion of the CO₂ in the well within the shale structure. This opportunity will change dependent upon the type of shale and nature of the shale formation, such as natural fractures, depth, surrounding geophysics, and related parameters.

Once separated from the gas or oil, the carbon dioxide may be left in the kerogen. It also could be reinjected in the well in a continuous cycle of extraction. The process can be managed as a continuous process with a configuration where a relief is opened which allows the natural gas and the expanding CO₂ to escape to the surface through the well and then the CO₂ can be separated from the natural gas for reuse or for storage in the shale bed. In some embodiments, one can use a design with the relief in the form of a point down the fracture from the injection point and forming a collection point. The sequestration can be performed either within the same well or to a second well.

One possible advantage is to leave as much CO₂ as possible in the well during and following well stimulation. The traditional uses of natural gas and oil result in the production of CO₂. One possible means of mitigating the effects of production of CO₂ is to inject it into the ground for storage, typically referred to as sequestration of the CO₂.

Most oil and gas bearing shales are from a period of geological development in which the gas and/or oil is starting to be released by the shale formation and is either trapped in the shale between layers or is slowly migrating towards the surface. This trapped gas and oil is different from the chemically bound hydrocarbons found in younger, less developed shale structures. However, in cracking the kerogen of the shale, the chemically bound material and smaller pockets of trapped materials can be released. This allows the possibility of extraction of hydrocarbons from young shales nearer to the surface and easier/cheaper to reach.

Our process is focused on chemistry and interactions of the shale with the fluid to allow for a lower pressure, non-brute force technique of opening up the shale for extraction of the gas. To accomplish this goal, the properties of supercritical solvents as evolved through the development of “green” chemistry (the design of chemical products or reactions which reduce or eliminate the use and generation of hazardous substances) are exploited in order to maximize the impact of the fluid with the shale.

The unique physical and transport properties of supercritical fluids (SCFs) are intermediate between those of a liquid or a gas, and they vary with density, which is a function of temperature and pressure above the critical point. SCFs provide the opportunity to engineer the reaction environment by manipulating temperature and pressure. CO₂ is most frequently used in supercritical processes because of its low cost and convenient critical conditions, with a critical temperature and pressure of 304.2 K and 72.8 atm, respectively). Supercritical (“sc”) CO₂ has also displaced halogenated and aromatic solvents in several industrial processes as an environmentally benign substitute. SCFs, and in particular scCO₂, reduce drastically the viscosity of heavy hydrocarbons or condensed phases, making them particularly effective in extracting organic components from oil shale. Mobility of the hydrocarbon phase is significantly increased because the surface tension of the hydrocarbon phase decreases drastically with the amount of dissolved supercritical fluid, which enables SCF mixtures to move freely in the small pores and microstructures that exist in oil shale formations.

We have investigated the utility of scCO₂ and several co-solvents for the extraction of petroleum from New Brunswick oil shale. The results obtained are encouraging, and indicate that a high yield of petroleum can be extracted from the shale using scCO₂ at low temperature and pressure, with up to 8% total weight of the material recovered as a medium-grade crude oil at ca. 13 MPa and 200-250° C. The morphology of the shale was significantly altered by this treatment, changing from an oily, resistive composite to a fine, dmy powdery clay which was recovered after the hydrocarbon was extracted.

The scCO₂ is able to enter the small pore openings in the shale (due to the specific properties of the liquid) and it can also react with the kerogen through absorption allowing some of the kerogen to be broken down and to release natural gas. This action is the initial opening of the shale and the start of the fracture. As the pressure drops, the solution formed between the reacting kerogen and the CO₂ rapidly expands leaving gas and a fine participate of the solids from the kerogen.

In situ, the CO₂ and a fraction of miscible products from the reaction with the kerogen are expected to convert from a supercritical “fluid” to a vapor, with significant expansion. This vapor is expected to continue to expand with decreasing confining pressure as it moves into the fracture. Flow velocities of the CO₂ from the surface to downhole are expected to increase accordingly as the pumps work to maintain pressure. Any mud, shale, powders, or other supercritical fluid in the well is expected to be pushed quickly into the fracture, leaving little hydrostatic pressure to resist influx of CO₂ into the fracture areas. The result is expected to be that more supercritical CO₂ flows into the fracture, expanding as it does so.

It is expected that the flow rate will eventually stabilize as equilibrium is established between backpressure caused by fluid friction from the fracture within the shale and the pressure drops across the formation face. This flow behavior is expected to be almost explosive in its violence as the fracture opens and continues to grow. Flow through small openings in the shale are expected to reach sonic velocity as the CO₂ expands within the fracture pore structure, and therefore, although violent in nature is not the traditional type of pounding that hydraulic fracturing typically provides. It is expected that eventually, the pumps are stopped allowing the pressure to drop and allowing the CO₂ to become gaseous. It can then be withdrawn from the well as a gas.

By having CO₂ enter the small pore structure and then rapidly expanding, the shale is expected to be fractured. More gas is expected to be pushed down the well to maintain pressure as monitored on the surface and the process may be repeated further expanding the fracture. It is expected that this process can be maintained as a slow and steady process at pressures around 1500-2000 psia or more violently and more like the traditional process at pressures around 10,000 to 12,000 psia.

It is expected that this process can be completed with a co-liquid carrying a proppant if a proppant is found to be needed. The scCO₂ can also carry a catalyst or co-solvent to allow for a reaction with the kerogen which will break down the kerogen and produce additional natural gas from the reservoir.

Studies conducted show that one result of treatment of shales with CO₂ for a period of time is the conversion of the shale into a powder. The pressure, temperature, nature of the shale, and time of the conversion can produce a variety of sizes and shapes of the powder. In addition, various additives are predicted to enhance or alter the conditions in which various sizes of powders are produced. This treatment of shales with CO₂ allows the use of the resulting powder as a proppant and does not require the addition of a proppant at the surface of, or from a source external to, the well. The treatment can be established such that the fracture rate, powder generated, and movement of the powder into the forming fractures can be controlled to allow for a low pressure self propping process.

Use of CO₂ as a green solvent is believed to be novel for the application of in situ upgrading and fracturing of the shales.

Advantages

Some of the advantages of the systems and methods of the present invention are believed to include the following attributes.

Many potential environmental advantages such as water reduction, seismic activity reduction, and CO₂ sequestration.

Water usage is reduced or completely eliminated.

Direct reduction in truck traffic and fuels used to power the trucks (approx. 1,400 truck loads of water per well).

Few or no chemical additives are required. Any chemical additives that are used are not hazardous.

Reduction (by way of example of 80 to 330 tons) of chemicals being pumped into the ground.

Some level of CO₂ sequestration achieved.

CO₂ used in the fracking can be recaptured and some level of the CO₂ will be left in the ground.

Reduction of formation damage (reduction of permeability and capillary pressure damage by reverting to a gaseous phase; no swelling induced).

The method encourages the formation of more complex micro-fractures, which can connect many more natural fractures greatly, increasing maximally the fractures conductivity.

Much less pressure placed on the shale and no repeated pressure as in the typical fracking process. The scCO₂ pressure is applied, left at high pressure for 2-3 days, and then released.

Enhanced gas recovery by displacing the methane adsorbed in the shale formations.

Evaluation of a fracture zone is almost immediate because of rapid clean-up. The energy provided by CO₂ results in the elimination of all residual liquid left in the formation from the fracturing fluid.

Better cleanup of the residual fluid, so smaller mesh proppant can be used and supply adequate fracture conductivity in low permeability formations (or in the present invention, no residual fluid would exist and no proppant would be used).

The use of low viscosity fluid results in more controlled proppant placement and higher proppant placement within the created fracture width (or in the present invention, we can readily move the fractured sediment to place as a proppant within the created fracture and eliminate the need for additional proppant from the surface.)

No need to dispose of the flowback fluids.

Further reductions in truck traffic as the flowback fluids don't need to be trucked from the well site.

Flowback materials often have levels of radioactivity due to the location in the ground, reduction in quantity of these materials leads to increased environmental safety to the site. Leads directly to reduction in truck traffic and fuels used to power the trucks (approx. 1,400 truck loads of water per well).

Easier and cheaper method to reach shales will become accessible for gas and oil extraction.

More shales can be utilized for production, opening up new sites and larger volumes of hydrocarbons.

FIG. 1 through FIG. 7 are presented to show that the mechanical systems that can be used to perform fracking are known. It is believed that the methods of the present invention can be performed using similar equipment in the above ground portion of the system.

Theoretical Discussion

Although the theoretical description given herein is thought to be correct, the operation of the devices described and claimed herein does not depend upon the accuracy or validity of the theoretical description. That is, later theoretical developments that may explain the observed results on a basis different from the theory presented herein will not detract from the inventions described herein.

Any patent, patent application, patent application publication, journal article, book, published paper, or other publicly available material identified in the specification is hereby incorporated by reference herein in its entirety. Any material, or portion thereof, that is said to be incorporated by reference herein, but which conflicts with existing definitions, statements, or other disclosure material explicitly set forth herein is only incorporated to the extent that no conflict arises between that incorporated material and the present disclosure material. In the event of a conflict, the conflict is to be resolved in favor of the present disclosure as the preferred disclosure.

While the present invention has been particularly shown and described with reference to the preferred mode as illustrated in the drawing, it will be understood by one skilled in the art that various changes in detail may be affected therein without departing from the spirit and scope of the invention as defined by the claims. 

What is claimed is:
 1. A method of producing a hydrocarbon from a hydrocarbon-bearing deposit, comprising the steps of: drilling a well into the hydrocarbon-bearing deposit; fracking the hydrocarbon-bearing deposit using CO₂ in the form of supercritical CO₂ as the fracking fluid, said fracking fluid lacking any water or particulates added from a source external to said well; and producing a hydrocarbon product from said well, said hydrocarbon product having a form selected from the group consisting of liquid form and gaseous form.
 2. The method of producing a hydrocarbon from a hydrocarbon-bearing deposit of claim 1, further comprising the step of: sequestering at least some of said CO₂ in said well.
 3. The method of producing a hydrocarbon from a hydrocarbon-bearing deposit of claim 1, further comprising the step of: sequestering at least some of said CO₂ in a different well.
 4. The method of producing a hydrocarbon from a hydrocarbon-bearing deposit of claim 1, wherein the hydrocarbon-bearing deposit is green shale.
 5. The method of producing a hydrocarbon from a hydrocarbon-bearing deposit of claim 1, wherein the hydrocarbon-bearing deposit is young shale.
 6. The method of producing a hydrocarbon from a hydrocarbon-bearing deposit of claim 1, wherein the fracking fluid is introduced using low pressure. 